To meet the demand for natural resources, companies invest significant amounts of time and money in searching for and extracting oil, natural gas, and other subterranean resources from the earth. Systems are often employed to access and extract the desired resource. These systems may be located onshore or offshore, depending on the location of the resource, and generally include a wellhead assembly through which the resource is extracted. These wellhead assemblies may include a wide variety of components, such as various casings, hangers, valves, fluid conduits, and the like, that control system operations. Sometimes it is difficult, as well as expensive, to get direct access to a well through the wellhead assembly while maintaining pressure-containing barriers to protect against release to the surrounding environment.
Wellhead assemblies may include a tree, i.e., an assembly of pipes, valves and fittings coupled to a wellhead housing or hub to control the flow of oil and gas produced from the well and/or to control the flow of fluids injected into the well, a spool, or other completion member. Completion members are manufactured for surface or subsea applications, and can be vertical, horizontal, or a variation or hybrid thereof in configuration.
Vertical completion members generally include one or more production passages containing valves, where each production passage is in-line with the production tubing. Vertical completion members generally may be removed while leaving the completion (e.g., the production tubing hanger and production tubing) in place; however, if it is necessary to pull the completion, a vertical completion member may be removed and replaced with a blowout preventer (BOP), a lengthy operation that may leave the well in a vulnerable condition during plugging and/or killing operations and/or exchange of the completion member and BOP pressure-control devices.
Horizontal completion members may be arranged with production control valves offset from the production tubing and with the tubing hanger locked and sealed in the member passage (instead of the wellhead) after the completion member is installed. With a horizontal configuration, the completion (e.g., the production tubing hanger and production tubing) may be removed without having to remove the completion member from the wellhead housing. However, if the member needs to be removed, the entire completion typically also is removed.
To manage expected maintenance costs, which are especially high for an offshore well, the well operator may select equipment best suited for the expected type of maintenance predicted to be required over the life of the well. For example, a well operator may predict whether there will be a greater need in the future to pull the completion member from the well for repair, or pull the completion, either for repair or for additional work in the well. Depending on the predicted maintenance events, an operator will decide whether the horizontal or vertical configuration, or a variation or hybrid thereof, each with its own advantages and disadvantages, is best suited for the expected conditions. For instance, with a vertical configuration, it is more efficient to pull the completion member and leave the completion in place. However, if the completion is pulled, the completion member is pulled as well, increasing the time and expense of pulling the completion. Conversely, with a horizontal configuration, it is more efficient to pull the completion, leaving the completion member in place. However, if the completion member is pulled, the completion is pulled as well, increasing the time and expense of pulling the member.
Another factor an operator may weigh in completion member selection is the relative bore size available for access. With the production valves offset from the production tubing, a horizontal configuration generally has a relatively larger bore. This allows the tubing and tubing hanger to be removed, for instance, or other downhole operations to be performed, without having to remove the completion member from the wellhead or disturb any external connectors to flowlines, service lines, or the like—thereby saving risk, time, and cost. Moreover, due to its large bore configuration, the horizontal configuration can accommodate larger equipment such as electrical submersible pump (ESP) completions.
An additional factor an operator may weigh in completion member selection relates to the operational impact of the so-called dual barrier requirement. Regulations in certain jurisdictions and other industry practices require a subsea well access system to provide at least two full-bore pressure-containing safety barriers between the well and open water environment at all times. For a vertical configuration, these barriers may be provided by valves such as master valves and swab valves, for example, which may be actuated to open at any time while a safety package is in place.
For a horizontal configuration, pressure-containing barriers may be provided by crown plugs sealed in the vertical passage of the tubing hanger above the production outlet and in the vertical passage of an internal tree cap landed in the completion member above the tubing hanger, where a so-called tree cap may be used with a tree, spool, or any other completion member. However, the well can be accessed only after the crown plugs have been physically removed. Removal and installation of crown plugs in a horizontal configuration each require a separate trip by wireline, slickline, braided line, or coiled tubing, and such subsea well intervention operations are generally very expensive, often based on hourly or daily rig charges. Moreover, in some cases the plug removal can be made more difficult due to the presence of corrosion, encrustation, debris, differential pressure across the plug, etc., thereby further adding to the cost of intervention.
An actuatable valve also may provide a pressure-containing barrier in one or more location. However, regardless of whether a crown plug or an actuatable valve is provided as a pressure-containing barrier in the tubing hanger bore, the location is problematic as tubing hangers may already have complex elements such as contingency plug profiles, for example. Moreover, providing a valve such as a gate valve in an internal tree cap as a final pressure-containing barrier may not provide complete control against leakage to the environment.